Oribi field is South Africa's first offshore crude oil production

Sept. 15, 1997
Oribi oil field, previously known as E-BT field, was discovered in mid-1990 when the E-BT1 borehole was drilled in the Indian Ocean. This borehole targeted a seismic amplitude anomaly at the same stratigraphic level as the 1988 oil discovery at the E-AR1 borehole 6 km to the northeast (Fig. 12 [39,438 bytes]). E-BT1 intersected 32 m of better quality reservoir sandstone than at E-AR1, the top 27 m of which were saturated with good quality, 42° gravity light oil and flowed up to 8,730 b/d

SOUTH AFRICA OFFSHORE E&P-2

Paul L.A. Burden, Christopher P.N. Davies
Soekor E&P (Pty.) Ltd. Cape Town
Oribi oil field, previously known as E-BT field, was discovered in mid-1990 when the E-BT1 borehole was drilled in the Indian Ocean. This borehole targeted a seismic amplitude anomaly at the same stratigraphic level as the 1988 oil discovery at the E-AR1 borehole 6 km to the northeast (Fig. 12 [39,438 bytes]).

E-BT1 intersected 32 m of better quality reservoir sandstone than at E-AR1, the top 27 m of which were saturated with good quality, 42° gravity light oil and flowed up to 8,730 b/d of oil with 3.4 MMscfd of associated gas.

Two appraisal boreholes followed, one of which, E-BT2 (2 km west of E-BT1) was intended as an updip test within a mapped westward extension of the E-BT1 reservoir. Only thin water-saturated sandstones were intersected here. The second, E-BT3 (1.65 km southwest of E-BT1) was drilled on the upthrown side of a minor fault thought to be non-sealing. Again, thin water saturated sandstones with minor oil shows were intersected in the reservoir interval. These were interpreted as being hydraulically separate, proximal equivalents of the E-BT1 reservoir.

Detailed zonation and volumetric determinations were carried out, and economic feasibility studies began. Conceptual development plans were formulated and reservoir simulation carried out. This led to the proposal to drill a further two boreholes with future production in mind.

E-BT01P was drilled in early 1993 as an additional production well to E-BT1. Spudded only 35 m from the E-BT well position and deviated at 15° to the southwest, it intersected a 29 m thick reservoir interval about 900 m southwest of E-BT1.

In early 1995, E-BT5 was drilled 2.3 km northeast (downdip) of E-BT1 as a future water injection well and was positioned to intersect the reservoir below the oil-water contact. As expected, the borehole intersected 26 m of water saturated reservoir sandstone, the top 4 m of which contained residual oil. Injectivity and pressure testing were carried out and showed that this borehole would be a suitable site for water injection.

After seismic reprocessing and remapping, final volumetric estimates were calculated, reservoir simulations performed, and a feasibility study carried out. Final project approval was obtained from government in mid-1995.

Geophysics, geology

The Oribi reservoir has a low acoustic impedance seismic response typical of other 14A deep-marine reservoirs, especially where they are hydrocarbon-bearing. On standard negative polarity data the gradational top of the reservoir corresponds to a peak of moderate amplitude while the sharp base corresponds to a high amplitude trough (Fig. 13 [22,565 bytes]) and (Fig. 14 [19,932 bytes]).

The reservoir has a distinct Geostack (AVO) response due to the volatiles associated with the light oil.

The field is located in the western, proximal, more channelized portion of the 14A deep marine lowstand play (Fig. 7).

The reservoir is a deep marine channel complex sourced from the southwest (Fig. 15 [26,348 bytes]). The sandstone body is elongated and trends SW-NE. The sandstones are encased in mud-rich overbank deposits. In the south the reservoir sandstones abut a small pre-existing scarp or flexure that controlled the southern margin of the sandstone body (Figs. 12, 14, and 15).

In the northeastern direction the sandstones are interpreted to be continuous into the E-AR area. However, E-AR is separated from Oribi due to compactional drape into a deeper graben at the level of the major Hauterivian unconformity, 5At1.

The reservoir has a sharp basinal contact overlain by 15-19 m of medium to coarse grained reservoir sandstone comprising numerous stacked massflow units. The top 15 m or so consists of finer grained sandstones with interbedded silt and shales in places and forms a gradually fining upward interval typical of channel abandonment (Fig. 16 [23,951 bytes]).

Sandstones are generally poorly sorted and very-fine to medium grained with some coarse grained and pebbly material near the base of the reservoir. They are generally clean but can be slightly argillaceous and include minor lithic and shell fragments. They are believed to have been derived from pre-existing sandstones of shallow, shelfal origin which are well developed in the western Bredasdorp basin.

The basal interval of the reservoir appears to be typical of the rapidly dumped products of high density turbidity currents. Large clay rip-up clasts are common near the bases of many individual massflow units. These were presumably eroded from pre-existing shales as the slurry rushed down the continental slope.

Water escape features and load casting are common, and slump folding has occurred in places. Individual massflow units seldom exceed a meter in thickness and are massive especially in high energy units near the base of the reservoir, although some do show crude upward fining. Amalgamated, sand on sand contacts separate individual units although occasional thin shale or silt interbeds are present in places.

The massflow units near the top of the reservoir interval are much finer grained and even silty in places. These often have fine horizontal lamination near their bases and ripple cross-lamination or climbing ripples near the tops. They fine upwards, and some are capped by thin shales deposited during local breaks in turbidite activity. These shales often contain deepwater faunas. Individual thicker shales have been used for detailed intra-reservoir correlations between boreholes. These finer units could be described as classical but incomplete Bouma cycles, the products of deposition from low density turbidity currents.

The reservoir is encased in thick deepwater shales that form a good seal.

Volumetrics

Reservoir properties are favorable for production. Porosities in the sandstones average 18% with a range of 13-24%. Permeabilities generally exceed 500 md and can be up to 2 darcies.

More than 80% of the total reservoir volume is considered to be net producible volume.

The most likely in place volume for Oribi field is 47 million st-tk bbl, but this could be as high as 74 million bbl. Project economics were carried out using the minimum volume (P90) of 32 million bbl. The areal extent of the field is about 6 sq km (1,480 acres).

Production

Oribi is 80% owned by Soekor E&P and 20% by Energy Africa Bredasdorp (Pty.) Ltd.

The field is produced through the Orca floating production facility, a converted, triple caisson, semisubmersible drilling rig formerly known as Sedco I. Oil is exported via a catenary anchor leg mooring (CALM) buoy to a shuttle tanker (Fig. 17 [27,132 bytes]).

The initial combined flow rate from the two production wells (E-BT1 and E-BT01P) is 24,000 b/d of oil with about 15 MMscfd of associated gas, which will be flared. Production will be choked back during periods of tanker disconnection or offloading operations, with up to 30,000 bbl of oil storage available in nine storage tanks within the three caissons.

Production started in early May 1997, and it is expected that at least 18 million st-tk bbl of 42° gravity light crude will be recovered from the field over about 4 years.

It is planned to bring nearby E-AR oil field into production through tiebacks to the Orca when Oribi production starts to decline. However, this second phase of the project has yet to be approved.

Participation openings

Current exploration efforts at the 14A level are concentrated in the area around Oribi field to increase the reserves within tie-back distance of the Orca floating production facility.

Since political change in South Africa during 1994, Soekor E&P has been promoting opportunities and seeking to establish further joint ventures for exploration within Block 9.

Eleven participation tracts have been defined, three of which are within the 14A deep marine play area. These are the E-BK, E-CB, and E-CN tracts.

A number of 14A prospects have recently been mapped in the E-CB tract updip of E-CB field. If successful they could be tied back to a single production facility over, for example, E-CB field, in the same way that it is planned to tie E-AR field into Oribi production.

The E-CN farmout tract includes the E-AM prospect, where encouraging oil shows have been encountered in the 14A sequence and oil saturation in thin sandstones in the underlying 13B sequence. Both of these tracts have additional potential in other plays at deeper stratigraphic levels.

Acknowledgment

We thank our colleagues at Soekor E&P for their support in providing and compiling data for this article.

The Authors

Paul L.A. Burden is a divisional geologist for Soekor E&P (Pty.) Ltd., where he has been a wellsite geologist, a development geologist, an exploration geologist, and an exploration team leader. He has experience of all South African offshore areas and has been involved in sequence stratigraphic analysis and geological modeling in all South African offshore basins as well as appraisal of gas fields in the Bredasdorp basin. He obtained an honors degree in geology from the University of Witwatersrand in Johannesburg in 1981.
Christopher P.N. Davies is a divisional geochemist for Soekor E&P. He joined the company in 1978 after doing base metal exploration in Europe and gold and copper mining in Namibia and South Africa. Following offshore rig time and regional exploration, he has supervised the geochemical section since 1980. He graduated from London University with geology honors in 1973 and is a doctoral candidate at the University of Stellenbosch.

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